The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
A present day substantive technical problem involves commodity “forward” trading in general, and the Exchange Traded Derivative (“ETD”) field in particular. Commodity “forward” trading, in general, represents a global market with currently outstanding notional values exceeding $4 trillion and annual turnover amounting to several times that level. The ETD field comprises about one fourth of the aforementioned market, but is poised for substantial growth if it can successfully attract commercial traders throughout the world, once the existing problem framed herein is solved.
Two platform types currently defining the prior art field allow commodities to be traded “forward” to hedge future production and consumption: 1) ETD platforms and “Over-the-counter (“OTC”) platforms. ETD platforms transparently execute contemporaneous bids and offers for a multitude of traders dealing primarily with standardized futures and options contracts. OTC platform deal with private agreements negotiated between market participants, with investment banks typically serving as intermediary market makers matching buyers and sellers. OTC agreements have more customized provisions than ETD contracts in order to satisfy the relatively complex demands of commercial counterparties (also known as “commercials”). But OTC platforms provide less in terms of counterparty credit protection and price discovery. More specifically, OTC agreements provide counterparties far less transparency over opaque private platforms and less fairness due to archaic value assessments published by price reporting agencies (“PRA”). Value assessment methodologies employed by PRA are labeled archaic because they merely track backward-looking samples of subscribers' already consummated spot/physical market transactions (per an “honor system” increasingly criticized by regulators around the world), rather than relying on fair market values openly generated by dynamic bids and offers contemporaneously executed and reported over a centralized exchange platform.
Each exchange serving the ETD market is typically supported by an adequately capitalized (and regulated) central counterparty (“CCP”) that matches buyers and sellers of contracts (the “counterparties”) and arranges for all payments and settlements attendant thereto. Under that support structure, counterparties do not incur direct credit exposure; thus, if a counterparty defaults on its ETD contract obligations, others are protected by the CCP. To maintain the viability of those arrangements while maximizing prospects for exchange trading volume and revenue growth, the conventional ETD contracts heretofore listed over centralized commodity exchanges have taken on the following characteristics:                highly standardized; as a result, they are relatively inflexible and thus primarily appeal to those traders willing and able to be matched up with absolute opposite interests;        specify one form of a denoted commodity to serve as a benchmark proxy for all forms of that commodity despite each among the plurality of forms commonly available having different quality and logistics characteristics; e.g., Brent and WTI are arbitrarily promoted as “global” crude oil benchmarks but they vary—in many cases substantially—from each other and most of the hundreds of other crude oil grades produced throughout the world; plus, this practice extends beyond the ETD field since PRA assessments referenced in OTC agreements are commonly based in one form or another on a conventional exchange-specified benchmark;        virtually never settle by physical delivery because daily trading volume and open interest levels have reached such heights that they commonly exceed the underlying benchmark's production output by extremely high multiples; there would seldom if ever be sufficient supply to meet that level of demand; and        specify delivery dates that are fixed, which presents big challenges for buyers and sellers of commodities (e.g., fuels) that require extensive logistical arrangements.        
Whereas standardized ETD contracts are easily tradable (evidenced by the market's high-frequency trading conundrum) and virtually always result in trades being reversed for a cash pay-out prior to expiration, private OTC agreements are typically maintained to maturity, underscoring their use by commercial traders despite aforementioned disadvantages of using opaque private platforms, etc.
In light of the foregoing, ETD contract use has grown considerably more appealing to speculators than commercials. The ETD field is therefore in need of innovation that will incorporate flexibility and customization needed to attract and serve commercial interests looking to benefit from the added liquidity and depth transpiring from the ability to trade alongside speculators and financial investors. Otherwise, the ETD field will become so inundated with speculator trading that it will be relegated to mere “casino” status. Many market participants claim that day has already arrived and that the ETD field needs innovative remediation immediately.
In summary, the substantive technical problem impacting commodity “forward” trading is that neither platform defining the field (conventional ETD or OTC) sufficiently meets all of the relatively complex needs of commercial hedgers having the desire to:
physically deliver or take delivery of commodities that typically have varying quality and logistics characteristics, the differentials of which need to be reconciled, balanced and subjected to financial settlements fairly determined in the open market; and
match with counterparties having practically rather than absolute opposite hedging interests, thereby benefitting from the added market liquidity and depth transpiring from such arrangements without being exposed directly to counterparty credit risks [the latter having gained considerable visibility—e.g. a la Dodd Frank—in the wake of the global financial crisis].
Global Trading of Financial Instruments
The global trading of financial instruments, in particular, has posed challenges because, heretofore, no particular exchange or benchmark has existed for trading instruments representing tradable assets such as commodities or financial instruments having dissimilar quality and/or logistics attributes that might impact relative values. In this regard the following discussion will focus on tradable financial instruments representing assets such as potash and fertilizers, as well as tradable financial instruments relating to assets such as credit instruments, cash or contractual obligations or rights.
Tradable Financial Instruments Involving Assets Such as Pot Ash and Fertilizers
Various portions of the potash-related background information noted below was derived from Independent Chemical Information Service (“ICIS”), part of the Reed Business Information group. For additional details, one may refer to www.icis.com/fertilizers/potash/price-reporting-methodology.
Potash aka potassium (chemical element symbol: K) is the seventh most common naturally-occurring element in nature, one of three main macronutrients required for plants. Crucial for all living cells to function, potassium aids in energy metabolism and, as an essential ingredient in various fertilizers, is a key agent in the plant growth process, creating the following benefits such as, but not limited to: 1) activating enzyme functions; 2) processing vitamins; 3) guarding against drought and disease; and 4) improving nutrient qualities of crops by inter alia strengthening their roots, thereby enhancing crop stability and yields. Whilst fertilizers consume over 90% of global potassium production, there are also industrial uses for potash (e.g., production of potassium hydroxide, water softeners, de-icing salts, other salt compounds, fireworks, soaps, glass and biodiesels).
Elemental potassium does not occur in nature because it reacts violently with water. As one compound or another, potassium makes up ˜2.6% of the weight of the Earth's crust. Some common rock formations contain potassium, such as orthoclase and granite. Large evaporate deposits from ancient lake and sea beds exist from which rocks are mined and then potash is extracted. Those rock formations include: Sylvite (KCl or potassium chloride); Sylvinite (KCl+NaCl or sodium chloride/haite); Carnalite (KMgCl or potassium magnesium chloride); Polyhaite; Kainite; and Laingbeinite.
Presently, the world's largest potash deposits are found in Canada and Russia, followed by Belarus, Germany, the Dead Sea (in both Israel and Jordan) and the U.S. The relative value of potash grades imported and exported is often reported in terms of their potassium oxide (K2O) equivalent content, which signifies the amount of potassium in fertilizer as if it were all in the form of potassium oxide.
Potash can be mined traditionally or by using more costly solution evaporation processes. Most potash mines today are deep shaft mines located as much as 4,400 feet (1,400 m) underground. Others are strip mined, having been laid down in horizontal layers as sedimentary rock. In above-ground processing plants, KCl is separated from the mixture to produce a high-analysis natural potassium fertilizer. Other naturally occurring potassium salts can be separated by various procedures, resulting in potassium sulfate and potassium magnesium-sulfate.
The most common potash fertilizer—muriate of potash (“MOP”)—comes in two formations: Standard MOP and Granular MOP. Standard MOP, used by relatively poorer countries for direct applications, is also used for chemical “NPK” production into various compound fertilizers that employ different nitrogen (N), phosphorous (P) and potassium (K) mixtures. Standard MOP is traded in larger volumes compared to granular MOP (noted below) because it's the potash of choice for two of the world's largest importers: India and China. For the most part, Standard MOP is traded according to the following terms:
FOB Vancouver;
FOB Dead Sea (Israel and Jordan);
FOB Baltic (Ventspils, Latvia);
CFR China (per contract prices);
CFR SE Asia (mainly Indonesia and Malaysia, as well as others); and
CFR India (note: India contracts tend to also be represented in the low range for FOB Baltic, Vancouver and Dead Sea prices).
Granular MOP, which tends to sell at a premium over standard MOP, is used in bulk blending for NPK production, as well as in direct applications in relatively wealthier countries using advanced soil fertilization methods. Granulation slows down absorption of fertilizer nutrients, prolonging their action. Granular MOP transactions typically take place according to the following terms:
FOB Vancouver—generally considered the “benchmark” of the group;
FOB Baltic (Ventspils, Latvia), albeit the bulk of granular MOP exported out of the Baltic goes to Brazil on CFR terms;
FOB Dead Sea (Israel and Jordan);
CFR Brazil; and
CIF within Northwest Europe.
The second most common potash fertilizer—sulfate of potash (“SOP”)—is a specialty product most frequently offered in granular form. Most SOP production methods require MOP to be used as a feedstock; thus, granular SOP sells at a premium over granular MOP.
SOP can be created by several methods, such as leaching, but for the most part is produced using the more traditional Manheim process, which calls for MOP to be treated with sulfuric acid. As such, changes in the price of MOP and sulfuric acid feedstock influence SOP prices. Following are different grades of SOP listed in the order of their relative cost—lowest to highest:
Standard grade SOP, which is most often used for direct application;
Granular grade SOP, which is predominantly used in bulk blending; and
Water soluble grade, which is used in specialized irrigation fertilizers.
Other formulations of potash include potassium nitrate (KNO3), potassium hydroxide (KOH) and potassium magnesium chloride (KMgCl aka carnallite). However, their trade volumes are relatively insignificant compared to MOP.
Producers of Potash and Fertilizers, their Customers and Logistics
Global potash production is concentrated in terms of both number of countries and companies in which it is produced, partly as a result of the location of potash reserves. Canada is the largest potash producer in the world (32% of 2011 global output), followed by Russia (19%), Belarus (16%), the Dead Sea (Israel and Jordan and Germany. On a company level, supply is even more concentrated, with the top five potash producers controlling over two-thirds of global supply belonging to one of two cartels.
Exports from Canada are coordinated through Canpotex, an international marketing & logistics company jointly owned by the Saskatchewan potash producers Potash Corporation of Saskatchewan, Inc., The Mosaic Company, and Agrium, Inc. The Potash Corporation of Saskatchewan, Inc. (“PCS”) is the world's second largest potash producer by output, with over 9 million metric tonnes shipped in 2011. Approximately one-half of this production went to North American customers. The Potash Corporation of Saskatchewan reportedly owns 54% of Canpotex. The Mosaic Company was launched in 2004 as a result of a merger between IMC Global (a fertilizer company whose origins date back to 1909) and Cargill's crop nutrition division. The Mosaic Company currently operates five mines, one in New Mexico and four in Canada, and is also the largest producer of finished phosphate products. The Mosaic Company reportedly owns 37% of Canpotex. Agrium, Inc. reportedly owns 9% of Canpotex.
As a competitive world supplier, Canpotex's logistics and delivery network employs bulk cargo vessels, storage facilities and thousands of specialized railcars catering to such foreign markets as Australia, Brazil, China, India, Indonesia, Japan, Korea and Malaysia. An extensive vessel chartering and brokerage network offers comprehensive ocean freight services to customers in those regions, enabling approximately 95% of all shipments to be transacted on Cost & Freight (“CFR”) basis. This provides Canpotex with the flexibility to combine cargoes (e.g., potash and sulphur) wherever possible to minimize ocean freight costs.
The Belarusian Potash Company (“BPC”), a joint stock company venture established in 2005 by Uralkali (Russian) and Belaruskali (Belarusian), is based in Minsk and supported by regional offices in New Delhi, Beijing, Singapore, Sao Paolo, Panama and Chicago. BPC supplies potash fertilizers to customers in Europe, India, China, Central and South America, U.S., Asia and Pacific, and Africa. During 2008, BPC's shareholdings were altered when Belarusian Railways acquired 5% of the company, thereby reducing Belaruskali's stake from 50% to 45%; Uralkali's 50% holding was left unchanged.
After months of rumors and denials that BPC was falling apart, it became official in July 2013 when Uralkali, the world's largest potash producer announced it would switch exports away from BPC to Uralkali Trading (its Swiss subsidiary) and abandon output limits that previously underpinned prices. Cooperation with its Belarus neighbor/partner ended because Belaruskali was reportedly undermining sales accords following an earlier Belarus government action, which cancelled BPC's exclusive right to export the nation's potash and fertilizer. After BPC's break-up, potash prices extended their earlier descent and volatility has intensified, which strengthens support for a centralized Global IMR e-Bourse to facilitate the hedging of potash and fertilizer price volatility.
Major shipments of MOP from Vancouver and Baltic (Ventspils, Latvia) into Brazil, India and China are shipped on Panamax vessels (>50,000 tonnes). Russian MOP products to the U.S. are shipped on Panamax, as well as Babymax (35,000 to 40,000 tonnes) and Handysize (15,000 to 35,000 tonnes; usually 25,000 tonnes). Most potash sold into Central and Latin America are Handysize cargoes, except for Brazil which often takes Panamax cargoes due to the size of its domestic market and high requirement for potash.
On occasion, product out of Ventspils and Chile (the latter shipped to Brazil) may involve combination cargoes with urea, usually on Handysize vessels. Dead Sea and Canadian MOP is generally never sold in combination cargoes and usually involve Panamax and Babymax vessels. German potash producers also send combination cargoes into Latin America, which contain a variety of potash, SOP and other salt fertilizer products.
SOP shipment volumes tend to be much smaller and generally involve bulk sales that are part (roughly 5,000 tonnes) of a bulk carrier, usually a Handysize. Water soluble grade SOP is usually packed in 25 kg bags loaded onto pallets placed inside containers in order to prevent water from impacting/ruining the product.
Pricing and Trading
At the present time, no centralized ETD platform exists to contemporaneously match buyers and sellers' orders of potash and related fertilizers using standardized conventional spot, futures and options contracts. As is customary in most major markets lacking centralized exchanges, “agency-assessed prices” are used to settle derivatives contracts and referenced in many physical market contracts.
ICIS, The Market quotes potash prices on a weekly basis worldwide on Thursdays and provides Market Updates on Mondays, Tuesdays, Wednesdays and occasionally Fridays covering the following:
Granular MOP, FOB Vancouver (stated in U.S. $ per metric tonne);
Granular MOP, CFR Brazil (stated in U.S. $ per metric tonne);
Granular MOP, FOB Israel/Jordan (stated in U.S. $ per metric tonne);
Granular MOP, CFR Southeast Asia (stated in U.S. $ per metric tonne);
Granular MOP, CFR China (stated in U.S. $ per metric tonne); and
Bulk SOP, FOB Northwest Europe (stated in euros per tonne).
ICIS provides price assessments for the above based on information supplied by market participants through the week up to the close of business on Thursdays at 17:00 hours in London. It should be noted that assessments by price reporting agencies (“PRAs”), such as ICIS, have come under increasing scrutiny by government regulatory bodies, market participants and the public at large. According to a Dec. 12, 2012 article published on pages 38-39 of the International Energy Agency (“IEA”) Oil Market Report (focused on natural gas and oil prices but can arguably be applied to any market void of a centralized exchange) titled Commodities: Extending Principles for Price Reporting Agencies to All Assessments—excerpts provided below:
Allegations of price manipulation in UK wholesale natural gas prices by major power companies and financial institutions could not have come at a worse time for PRAs. Less than a month after IOSCO's publication of principles for oil price reporting agencies, a price reporter at energy-industry data provider ICIS went public with the charge that natural gas prices are regularly manipulated by physical and financial traders, and that prices assessed by PRAs do not accurately reflect the underlying physical market. Furthermore, he argued that poorly trained price assessors often developed close relationships with traders, which led them to routinely engage in Libor-style price fixing exercises. Immediately following these allegations, UK Financial Services Authority (FSA) and energy regulator Ofgem launched investigations into the claims.
Market participants have long claimed that selective reporting by traders and inconsistent methodologies used by PRAs can distort reported prices. These concerns were the basis of a report published by IOSCO in early October, to which the IEA, OPEC and the IEF, responding to a request from the G20, provided input. The report suggested that “ability to selectively report data on a voluntary basis creates an opportunity for manipulating the commodity market data that are submitted to PRAs” and “the need for assessors to use judgment under some methodologies creates an opportunity for the submitter of data to deliberately bias a PRA's assessment in order to benefit the submitter's derivatives positions.”
In order to enhance reliability of oil price assessments that are referenced in derivatives contracts subject to regulation by its members, IOSCO set forth a set of principles—a framework of best practices—for the PRAs to follow. IOSCO proposed, in collaboration with the IEA, IEF and OPEC, to review the implementation of said PRA principles after 18 months. If implementation is ineffective, there may be further recommendations.
PRAs initially argued that they are basically news agencies and they are simply using their freedom of expression rights, therefore they cannot be subject to such rules. IOSCO overcame this objection by restricting these principles to be applied only in price assessments referenced in oil derivatives contracts. Practically, they recommended that “market authorities consider whether to prohibit trading in any oil derivatives contract that references a PRA-assessed price unless that assessment follows the PRA principles.” It is a rather indirect way to force PRAs to adopt such rules. Instead of losing their customer basis, PRAs are expected to adopt these proposed principles.
While a step forward, these principles still do not fully address the problem of selective price reporting. Since traders are not required to submit trade data to PRAs, there is a risk that voluntary reporting could result in selective reporting and thus seriously compromise the integrity of price assessment. Therefore, it is arguably quite important to allow PRAs to use more information than merely concluded transactions when making price assessments. Exclusive reliance on concluded transactions can lead to inaccurate price assessment if submitted prices are false or manipulated. Thanks to use of other market information, PRAs can check the accuracy of submissions or assess whether submitted prices truly reflect the market place. Demanding traders who chose to voluntarily submit data to provide all of their market data in order to prevent selective reporting is not the answer. Given the voluntary nature of trade reporting, asking traders to submit all of their trade data amounts to an “all or nothing” policy which runs the risk of effectively discouraging price reporting and drastically limiting the pool of information available to PRAs, thereby adversely affecting the reliability of their reports. As long as the submission of data is voluntary, there is a strong risk that such “all or nothing” policy could end up fatally disrupting the flow of information from submitters to PRAs.
Another weakness in these principles has to do with complaint-handling. While they do call for a formal complaint-handling policy, the principles stop short from requiring disclosure of complaints to market participants. The principles require PRAs to advise plaintiffs and any other relevant parties of the outcome of an investigation in the event of a formal complaint. Disputes regarding a daily pricing determination will be communicated to the market only when a complaint results in a change in price. However, if the aim of these principles is to increase transparency in price assessment, it may be argued that they should have called for an immediate announcement of all accepted formal complaints to market participants, similar to announcements of trade errors occurring at exchanges. Furthermore, the principles called for recourse to an independent third party review of complaints if the plaintiff is dissatisfied with the way a complaint has been handled by the relevant PRA. However, the principles require that the independent third party be appointed by the PRA itself. Giving the right to appoint the third party to the PRA to review its own decision clearly creates a conflict of interest and undermines the independence of the external review. To ensure an independent review process, the appointment of the third-party reviewer should be jointly handled by the PRA and industry stakeholders.
It is important to note that PRAs deliver more than just news. Their assessed prices are used not only in settlement of oil derivatives contracts but also in other derivatives contracts, including but not limited to natural gas and refined products. These assessed prices are also referenced in many long-term physical market contracts. The recent allegations of price-fixing in UK wholesale gas prices show the importance of reliable price assessments. Therefore, the principles developed for oil price assessments that are referenced in derivatives contracts should be universally adopted by PRAs for any price assessment activities.
ETDs Related to Fossil Fuels
Historically, the prices of a large number of fossil fuels such as crude oils and refined products have been set either by oil producing countries or determined by the spot market. The Organization of Petroleum Export Countries (OPEC) official selling price system for all intents and purposes ruled the crude oil market from the early 1970's to 1985. Under the OPEC price system, most crude oil sales were transacted as part of long-term contracts having fixed prices and volumes, with price adjustments made infrequently. However, over the years, more crude oil trade has taken place using spot and futures prices and contract sales have entailed shorter durations and more flexible terms.
Spot pricing has become widely accepted in energy markets since the U.S. opted to deregulate energy prices about 30 years ago. Under the spot pricing system, many different crude oil prices are set differentially to the price of one or more benchmarks. Crude oil benchmarks (also known as “markers”) were introduced in the mid 1980's. Most term contracts are now linked to the spot prices of benchmark crude oils, rather than priced at an outright level.
The use of futures and options contracts for energy commodities became more popular in the 1980's, more than a century after commodity exchange trading commenced in the U.S. and Europe. Futures contracts enable owners of assets to obtain price protection against adverse price movements. The buyer is obligated to purchase an asset (or the seller to sell an asset) at a predetermined future date and price. Futures contracts specify the quality and quantity of the underlying asset and are standardized to facilitate trading on exchanges that are typically registered with and regulated by one or more governmental organizations.
While holders of futures contracts are obligated to buy or sell the underlying asset at expiration, an options contract gives the holder the right to buy or sell. Thus, options can be a used as means to hedge futures contracts.
Whereas futures and options contracts are traded over a centralized exchange, another form of hedging involving use of over-the-counter (OTC) derivatives agreements has gained popularity, albeit amid mounting controversies and closer scrutiny from government regulators, as well as the population at large. OTC derivatives are bilateral contracts whereby two parties agree on how a particular trade is settled in the future, with the three most common contract types being:
Forwards: agreements to exchange at some fixed future date a given quantity of a physically delivered commodity for a currently defined price.
Swaps: financial agreements settled by cash rather than any transfer of the underlying commodity, which provides price protection for an agreed quantity of a commodity on an agreed future date (usually greater than one month but less than two years after the trade date).
Spreads: agreements designed to allow producers to lock in differentials between commodity prices at different times (“calendars”) or between different commodities (“cracks”); in either case, the purchaser/producer pays a pre-agreed fixed spread level in exchange for a floating spread level obtained from the provider in transactions that are usually financially settled.
Most OTC derivatives involve the use of intermediary banks, rather than any centralized exchange, to serve as counterparties matching buyers with sellers. In the process of becoming prominent (if not dominant) OTC derivatives dealers, some of the world's largest banks stand accused of making markets that lack transparency (i.e., in terms of price discovery, volume and counterparty risk) in order to generate large profits at the risk of incurring major losses in the event that counterparties fail to honor their committed trade obligations.
OTC derivatives drew heavy criticism in the aftermath of the Enron scandal of about 2001 and more recently came under even closer scrutiny as the unbridled proliferation of Credit Default Swaps and other OTC instruments led to the demise of Bear Stearns, Lehman Brothers, AIG et al, as well as the ensuing financial crisis that morphed into the Great Recession. As a result, several regulatory initiatives have emerged globally to alter the future of OTC derivatives use. The goal of these regulatory initiatives is to ensure that private contracts between counterparties will become transparent instruments settled by central clearinghouses imposing stricter margin policies to enhance credit risk management and publish more fulsome order, price and volume data.
Major regulatory initiatives on the docket include the Dodd-Frank Wall Street Reform and Consumer Protection Act and similar measures being pursued outside the U.S.; more rigorous capital, leverage and liquidity standards from the Basel Committee on Banking Supervision; and International Financial Reporting Standard No. 9 promulgated by the International Accounting Standards Board. The initiatives call for, inter alia, substantial changes in classifying and measuring financial instruments, the wider use of “mark-to-market” rules and increased hedge accounting and disclosure requirements, as well as for the instruments to be centrally cleared and settled by qualified clearinghouses imposing margin rules. In all likelihood, such initiatives will intensify regulatory capital pressures on banks and affect the ability of, and the means by which, banks maintain their liquidity. As a result, some banks will undoubtedly be curtailed if not precluded from dealing in OTC derivatives and in that process the types traded in the past may become less liquid and thus less attractive to trade.
In most cases involving exchange-traded energy futures and options, as well as OTC derivatives, benchmarks indicate crude oil quality and geographic location. They are useful referencing tools for buyers and sellers because there are so many varying grades of crude oil produced throughout the world. According to the International Crude Oil Market Handbook published by the Energy Intelligence Group, there are around 200 crude oil blends produced in 46 countries, all varying in terms of characteristics, quality and market penetration. Following are the most common crude oil benchmarks used in global commerce:
West Texas Intermediate (WTI) is light sweet crude oil with 39.6° American Petroleum Institute (API) gravity, 0.24% sulfur content and a delivery point in Cushing, Okla. (USA). Although WTI is a U.S. grade of crude oil, it has attained global benchmark status, inter alia because WTI futures and options contracts amassed substantial trading volume gains in the past decade or so from speculators and financial investors around the world. In addition to being a spot market bench-mark, WTI futures and options trade in denominations of 1,000 barrels per contract at the CME Group Nymex (formerly New York Mercantile Exchange) and at the Intercontinental Exchange (ICE) in London.
Brent is comprised of five (5) light sweet crude oil grades with blended API gravity of 38.06° and 0.37% sulfur content. Sourced from the North Sea and refined mostly in NW Europe, Brent is also touted as a global benchmark, in particular for large tanker shipments heading west to North America from Europe, Africa and the Middle East. Brent futures and options are primarily traded at the ICE in denominations of 1,000 barrels per contract. Prior to September 2010, there were typically fairly small WTI-Brent price differentials (+/−$3 per barrel, with WTI usually exceeding Brent due to higher quality API gravity and lower sulfur content). However, in late 2010, differentials diverged from the previous norm, expanded and eventually exceeded $18 per barrel in March 2011—with Brent exceeding WTI—due to a variety of factors detailed later herein, all of which has prompted concerns about the extent to which Brent and WTI will be able to maintain their status as global benchmarks.
DME Oman Crude Oil futures and options are listed at the Dubai Mercantile Exchange (DME; a collaborator and affiliate of the CME Group), traded in denominations of 1,000 barrels per contract and specified as having API gravity of 31.0°, 2.0% sulfur content and a delivery point in Oman. DME was launched in June 2007 with a goal to bring about fair and transparent price discovery and efficient risk management to the East of Suez market, considered the fastest growing commodities market and largest crude oil supply and demand corridor in the world. DME Oman Crude Oil is the explicit and sole/official selling price benchmark for Oman (output of 812,000 barrels per day or bpd) and Dubai (output of 54,000 bpd but in decline), which have purportedly been viewed (at least by the DME) as markers for heavy sour ME crude oil grades exported to the Asia-Pacific region. However, due to some limitations associated with inter alia an Oman delivery point and the relatively small output of marker oil fields in Dubai and Oman, the average daily volume (ADV) of DME Oman Crude Oil futures and options contracts are arguably well below the levels reasonably expected for a viable global (or even regional) benchmark, to the point such that, as of the end of 2009, the CME Group elected to write off the $28.6 million carrying value of its investment stake in the DME because it was impaired.
Argus Sour Crude Index (ASCI) is listed at the CME Group's Nymex and the ICE. ASCI is based on three medium sour Gulf of Mexico crudes (Mars, Poseidon and Southern Green Canyon) with a blended average of 29.3° API gravity and 2.03% sulfur targeted for processing by U.S. Gulf Coast refineries. So far, ASCI has been adopted as a benchmark (subject to a myriad of differential adjustments) for spot market sales by Saudi Aramco and Kuwait Petroleum (in 2009) and Iraq's Somo (in 2010). ME crude oils priced against ASCI include Arab Extra Light, Arab Light, Arab Medium, Arab Heavy, Kuwait Export Blend, Basrah Light and Kirkuk. While ASCI might well be more suitable than the light sweet WTI and Brent benchmarks for spot markets and long-term contract arrangements negotiated by ME exporters with U.S. Gulf Coast refineries, ASCI pricing and other methodology (see www.argusmedia.com/methodology) is arguably too cumbersome to generate efficient futures and options contract trading on a wider global scale, especially in connection with ME exports to East of Suez markets, which inter alia include India, Singapore, Hong Kong, China, Taiwan, South Korea and Japan.
Urals is a reference oil brand used as a basis for pricing a principally Russian export oil mixture (specified with 31.8° API gravity and 1.35% sulfur) extracted from the Urals and Volga regions along with lighter crude oils from Western Siberia. It is supplied through the Novorossiysk pipeline system and over the Druzhba pipeline. Urals futures trade on the Russian Trading System (stock exchange), as well as at the CME Group's Nymex, where it is known as Russian Export Blend Crude Oil (REBCO). While Urals are not yet material to the context of this hedging apparatus, they are nonetheless noted due to the planned increase of crude oils to be exported from Russia to China over the newly opened ESPO (Eastern Siberia to Pacific Ocean) pipeline delivering Russian oil to energy hungry China.
In assessing the benchmarks noted above, it becomes clear that, for all intents and purposes, the CME Group's Nymex and the ICE, along with their affiliated exchanges around the world, enjoy a virtual duopoly in the global crude oil futures and options trading arena, as currently shaped. Perhaps more than anything else, this reflects the fact that WTI and Brent are prime light sweet crude oils coveted by highly regulated refineries for their low sulfur content and efficiency in generating high quality refined products. Compared to ME crudes having relatively lower API gravity and higher sulfur content, WTI and Brent are much easier to refine into cleaner gasoline (generally 30 ppm sulfur content) and diesel (generally 10-15 ppm sulfur called ultra-low-sulfur or ULSD) fuels mandated by U.S., West European and other (OECD) government environmental protection agencies (EPAs).
However, that model is not practicable for the rest of the world, where sulfur levels in gasoline and diesel fuels often amount to 500 ppm in major developing countries and several thousand ppm in others. Huge investments would be required for those countries to substantially change over (or build new) refineries to implement cleaner engine, fuel and emission control programs, which could take decades to rationalize and fund. That assumes it would even be feasible or affordable to do so, at all, since the light sweet crude oil phenomenon known as Peak Oil (discussed more fully later herein) lurks in the background. In that event, creating even greater (non-OECD) demand for light sweet crude oil resources would likely cause hyper-inflation on a global scale capable of crashing most, if not all economies. That approach seems foolish, even wasteful, considering that there are much larger (and growing) reserves of relatively heavier and sour crudes that can be tapped well into the future.
WTI and Brent futures and options traded at CME Group's Nymex and the ICE have appealed to Western/OECD buyers and sellers, especially those indulged speculators who have skyrocketed their open interests while creating volatile/spiraling prices via high frequency trading programs that demand trade execution speeds of single digit milliseconds (and headed for microseconds), thereby driving ADV to record heights. WTI and Brent have also been tolerated in the past by ME exporters and their customers wanting to hedge but lacking better alternatives. In doing so, they have resorted to complex Platts and Argus (specialist energy publishers) assessment-based OTC derivatives, often using one or the other as their benchmark but requiring numerous differential adjustments, an overly complex and increasingly inefficient exercise due inter alia to increasingly apparent flaws with these benchmarks.
As mentioned above, the WTI-Brent spread has gone from being relatively tight to a scenario whereby WTI now sells at a considerable (often $10+ per barrel and recently $18+ per barrel) discount to Brent, even though WTI is higher quality crude and it costs extra to ship Brent to the U.S. This anomaly may be attributed to several factors.
First, having WTI's delivery point in Cushing, Okla., is limiting and storage has become problematic, even though capacity has steadily been raised to handle an influx of Canadian crudes coming in via pipeline, along with the new oils produced in North Dakota that have caused aggregate U.S. crude output to just increase for the first time in 23 years. Because it is easier to move oil from major producing regions to Cushing than to move oil from Cushing to refineries (especially U.S. Gulf Coast refineries that also import ME crudes) and consumers, the supply bottle-necks being created there are not expected to go away any time soon. WTI prices are expected to remain in a substantial discount mode (to Brent) and thus be less appealing to traders of ME crude oils.
Further complicating matters, North Sea oil production is declining while European and Asian (especially Chinese) demand for diesel and other distilled products has increased. It should be noted that, whereas WTI tends to generally be more favorable for gasoline products, Brent generally tends to favor production of diesels and other distillates. Thus, added distillate demand for Brent in the face of lower North Sea production has caused supplies to decline and prices to rise. Adding to the fray is the recent turmoil in Africa (especially countries with desirable low sulfur crudes, such as in Libya) and the ME that will not likely be resolved any time soon and could grow worse, all of which currently tends to be reflected more in Brent prices than WTI. The bottom line is that WTI and Brent each have exposed flaws that are causing traders to question their viability as global benchmarks, especially as it relates to crude oils produced in the ME.
It is generally recognized that market prices of so-called “landlocked” crude oil have become increasingly impacted by qualitative factors other than API gravity and sulfur content. This particularly holds true in North America (NA) where production levels have surged in the last few years and are projected to continue to increase. The relative geographic location of producer wells and terminal facilities on one hand versus customer refineries on the other, plus a slew of logistics challenges converging midstream to create bottlenecks, have spawned intermodal permutations, including those pertaining to inter alia pipeline, boat, rail and/or truck solutions, each of which is integral to current market dynamics, thus generating substantial price differentials. Such factors lend support for novel hedging instruments, such as those originally specified in the Parent Application and advanced herein, to help market participants better manage risks of price movements in the future.
The crude oil market in NA is undergoing enormous change. Structural shifts resulting from U.S. light sweet oil shale plays at Eagle Ford (below much of South and East Texas) and Bakken (below parts of Montana, North Dakota and Canada's Saskatchewan province), as well as a growing influx of Canadian oil grades competing for strained (albeit gradually growing) storage and transportation infrastructure in the U.S., have caused significant price dislocations leading to calls for greater market transparency.
According to industry experts, such structural shifts will likely prompt pricing alternatives to West Texas Intermediate (WTI), which until quite recently was NA's singular crude oil benchmark for all intents and purposes. The convergence of such factors as rising Canadian and Bakken production, in tandem with pipeline capacity shortages within the crucial midcontinent to U.S. Gulf Coast (USGC) corridor, have steadily weakened WTI prices the past couple of years versus those for USGC domestic grades and the major international waterborne blend, Brent. Already, there are cases involving the referencing of Eagle Ford sales to Louisiana Light Sweet crude prices.
It remains desirable to provide more alternatives for cases dealing with landlocked crude oil delivered to designated (principally refinery) destinations via intermodal permutations involving inter alia storage terminal, pipeline, boat, rail and/or truck solutions.